HPHT Well Cementing Challenges

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Lenin Diaz
Lenin Diazhttp://better-cementing-for-all.org/
Fluids and Cementing Specialist. Technical and Operational Expertise in Fluids, Cementing, Water Control and Shut-Off. Owner and Founder of 'Better Well Cementing For All'. drillers.com expert

In recent days I have been reading some posts mentioning specific challenges in HPHT well cementing. (For example, those related to laboratory testing and gel strength). I felt moved to offer a broader view of this cementing application. Understanding the consequences of temperature on cement hydration is fundamental to achieving success in the high density realm of fluids.

The High Pressure/High Temperature classification applies to any well, if the bottom hole temperature is at least 150 oC with a pore pressure higher than 10,000 psi. These extreme values challenge the well construction process in several ways, including themes of well control, drilling equipment durability, sealing elements, drilling and completions fluids. Still, well cementing is particularly difficult due to its sensitivity to temperature, which has a tremendous effect on the reproducibility of results, making every job unique and the subject of careful engineering and laboratory testing.

Before going in detail let’s understand the basics. First, temperature accelerates the hydration process of cement hence limiting the time it remains as a maneuverable slurry in the well. For our purpose refers to its capacity to flow within a defined operational window. Chemically, a quicker hydration process can be delayed by the addition of certain materials known as retarders. However these have side effects, which vary depending on the chemical nature of the retarder, its quantity, presence of other components, and the characteristics of the cement. In summary, the higher the temperature the more noticeable these side effects will be, but this is not the limit of our consideration. Higher concentrations of cement, required in some cases to achieve higher density (high formation pore pressure), will amplify the occurrence of all the chemical reactions involved triggering even more adverse behaviours in the cement slurry,

Now let’s go back a little with some definitions. What is the objective of primary cementing? I would say the main objective is maximizing cement coverage. Therefore targets like zonal isolation and casing protection can only be achieved if cement presence is maximized in the annular gap; In other words: cement coverage. However, cement coverage is only possible if mud is completely displaced from the hole during cementing. Consequently, in HPHT one of the most detrimental chemical side effects is seen in the cement slurry rheology and its role in achieving sufficient mud displacement in a high fluid densities environment.

Now, what are the exact implications of dealing with high-density fluids? First of all, high-density fluids are required because of the high formation pore pressure to keep primary well control. This calls for high mud density, which in turn demands high-density cement slurries. In summary, the implications for the cement slurry itself and its placement are:

  • Lower-than-desired pumping rates due to limited Equivalent Circulating Density or ECD. It is common in HPHT wells to have a narrow margin between fracture and pore pressure limiting the allowable displacement rates and ECD, not to exceed the fracture gradient (induced losses);
  • Lower pumping rates prevent in most cases achieving proper density and rheology hierarchy, thus making more difficult mud removal;
  • Lower pumping rates; also call for higher concentrations of chemicals, especially retarders, to allow longer thickening times.

Now talking about the high-density cement slurry features:

  • It must be stable and pumpable at surface and at high circulating temperature;
  • It must also be sufficiently retarded (to be pumpable) and be still able to set at the top of cement (at lower temperature);
  • It requires a careful design conscious of changes in small temperature variations, cement batches, density variations and additive concentrations;
  • It must acknowledge the limitations in laboratory testing;
  • High-density cement slurries are more difficult to mix at surface and they have high solid content, which favour settling (stability issues) and/or gelling (high rheology). These chemical processes are temperature-dependent.

It must be clear at this point, that designing an adequate cement slurry system able to meet and endure the predicted requirements, by the hydraulic simulation, is fundamental. The most important of these requirements, as previously mentioned, is rheology. Here are some recommendations:

  1. Surface conditions (mixability), 300 rpm reading < 300 and Yield point lower than 35 lbs/100 ft2;
  2. Yield point higher than 10 lbs/100 ft2 at high temperature (conditioning in HPHT consistometer or at 185 °F);
  3. If available during job planning, use HPHT rheometer to measure, at least, the mud rheology. This will be required for a more accurate hydraulic simulation. (HP/HT rheometer or viscometer is used to monitor the temperature stability of the drilling fluid, and to evaluate its rheological properties at up to 260 °C and 20,000 psi);
  4. Ramp-up to ramp-down readings at each speed (300, 200, 100, 60, 30, 6, 3 rpm’s) ratios to be close to 1. Higher ratios suggest settling tendency and lower ratios could be an indication of a gelling tendency;
  5. Initial consistency on the HPHT consistometer recommended to be below 30 Bc
  6. Check for a consistency spike in the HPHT consistometer when the motor is shut-off (Go/No-Go Test). This is an indication of static gel strength development and it simulates what would happen during static periods, e.g., dropping wiper plugs, before circulation on top of the liner hanger;
  7. Zero free fluid (if well is deviated run test at an angle);
  8. Static Sedimentation test, less than 5 % deviation from theoretical density;
  9. API Fluid Loss < 50 mL/30min. Use stirred fluid loss cell;
  10. Run mud/spacer/cement compatibility test for rheology and thickening time (UCA as well in case of OBM). In thickening time include Go/No-Go check. If available, for liner jobs check for static gel strength of the contaminated mixture (this is important to ensure contaminated cement on top of the liner hanger can be circulated out). NOTE: cement contractor should make a recommendation for the length of the overlap;
  11. Run sensitivity tests. For temperature (check for top of cement), retarder concentration (+/- 5% BWOC or 0,02 gps) and density (+/- 0,3 ppg, depending on surface mixing methodology and controls).
  12. Emphasis must be to allow for sufficient thickening time (as per applicable policy) while avoiding excessive time to reach 50 psi compressive strength to minimize waiting-on-cement time.

Finally, well construction in HPHT condition implicates several challenges, with wells often deep and having narrow pressure operational window, undesirable long non-productive times and higher-than-planned costs. Proper cementing can provide tremendous benefits to keep positive well economics. Consequently, this post was intended to highlight some of the considerations that are important to well cementing in HPHT conditions. I hope you find its content helpful and if there are any questions or comments please drop them in the dedicated area below.



  1. Another remarkable article Lenin, your insights into design and implementation of risk managed cementing are second too none.

  2. Also please read my below mentioned SPE papers on HPHT and Ultra HTHP cementing for proper technologies:
    1) HPHT Cement System Design – East Coast Case History
    2) Best Practices in Designing HP/HT Cement-Plug Systems
    3) HP/HT Well Intervention by Coil Tubing – East Coast Case Histories
    4) Coalbed Methane Cementing Best Practices – Indian Case History
    5) Improved Zonal Isolation in High-Temperature Offshore Wells with an Advanced Lightweight Cement Design – Gulf of Thailand Case Histories

  3. Hi Lenin, nice summary. Well done. Regarding the sensitivity testing on thickening time, due to uncertainty in the BHST estimation we also do tests at higher and lower temperatures, say, just for example, +/-15° F. Also, it’s extremely important to double check that the lab tests are done with the samples of additives from the same tank/lot number, mix water and bulk cement taken from the rig. Also, in deep well liner jobs the torque and drag limitations may prevent the ability to rotate the liner, so the other factors that affect good cement coverage/mud displacement may need to be enhanced in order to compensate, for example: maximizing the density and rheology hierarchy of the fluids, centralization, pump rate, mud conditioning to lower its rheology as much as possible without inducing barite sag, additional mud pre-job circulation and conditioning, and planning the operations to minimize the shutdown time between stopping mud circulation and starting the pumping of the cement job itself in order to avoid excessive mud gelation. Keep up your good work with these posts.

  4. I find myself still a student (your student) when I read your words Mr. Lenin, keep your mind/finger flowing with such article on this website because it make the whole site worth to have a look on.

  5. Very useful summary. As you rightly said, all jobs should be handled on individual basis; different batches of cement , water and additives can make reproducibility of test results difficult. Another point to note is the reliability of lab equipment. They should be calibrated in a timely manner so results churned out can be reliable.

    • It is good you mention that Selorm. In HPHT cementing we are always walking a fine line between success and failure. Reliability of laboratory equipment is of great importance for any of the test results to make any sense, including variations in thickening time sensitivity tests and rheology, for instance.

  6. There are days when you just want to quit, like all jobs. However, Northern Oilfield Services points out that the oilfield rewards those richly who never give up and who stick it through to the end.

  7. Good summary Lenin. We can had as well the importance of testing all slurries with representative rig samples including water to avoid any issue (but this applies for all operations not only HPHT).
    Also I like to set a peak limit to 40Bc for the Go/No Go TT tests, to be sure that in case displacement is stopped, we can safely resume cement job.
    For Free Fluid, it is also good for HPHT to consider running the test by default at 45 deg inclination even for vertical section, “stress test”.

  8. I work for a small drilling engineer company and just got assigned to look at high temperature effects during well testing. Any input on were to start to gather litterature etc is wellcome


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